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PAB 4323 – WELL STIMULATION

TECHNIQUES

SEMESTER 7

By

Dr. Aliyu Adebayo Sulaimon([email protected])

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Course Major Contents

Well stimulation techniques

Reasons for stimulating

Primary forms of well stimulation• Wellbore clean-up

• Matrix treatment

• Fracturing

Candidate selection

Selecting a technique

Assignment and Review

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Learning Outcomes

At the end of this lecture, students should be able to: Describe how flow capacity reduction can occur

Describe what is a good stimulation candidate

Name the three primary stimulation methods

Describe the difference between matrix and fracture

stimulation

Know the two types of fracture stimulation

Describe the two types of fracturing technique for low and

higher permeability formations

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Figure 1: Components of sedimentary rocks

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Purpose of Stimulation

To enhance the property value by the faster delivery of the petroleum fluid

To increase ultimate economic recovery

Flow Near Wellbore

Skin effect „S‟ is used to describe alterations in the near-wellbore zone.

Recall, permeability damage is a common problem caused by practically any

well operation e.g. drilling, completion, perforation or stimulation itself

If „k‟ is significantly reduced, then the largest portion of the total pressure

gradient may be consumed within the very near wellbore zone

=

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Increase production efficiency or flow capacity• Overcome formation damage

• Enhance production from low permeability wells

Connect with natural fracture system

Increase effective drainage area

Produce complex reservoirs (e.g. discontinuous sand bars)

Increase wellbore stability (minimize drawdown)

Reasons for Stimulation

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Stimulation Techniques

Basically, there are three ways of well stimulation: Wellbore Clean-up (Fluids not injected into formation)

Chemical Treatment

Perf Wash

Matrix Treatment (Injection below fracture pressure)

Chemical Treatment

Matrix Acidizing

Fracturing (Injection above fracture pressure)

Acid Frac

Propped Frac

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Candidate Selection

Requirements:

Selection of candidate wells

Selection of the specific treatment

Design

Economic Justification (Do or not)

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Selection of candidate wells

Good candidates

Damaged wells

Tight reservoirs (refer to the journal articles provided)

Medium candidates

Naturally fractured reservoirs

Unconsolidated, high permeability reservoirs

Bad candidates

Limited reserves

Low pressure reservoirs where fracture fluid flow back forcleanup is difficult (in case of hydraulic fracturing)

Stimulation and reservoir fluids not compatible

If stimulation can penetrate water zones (water production)

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Selection of Treatment Technique

Productivity target, drawdown limit and zonal isolation determine

the stimulation technique

Productivity

Sandstone reservoirs• Matrix stimulation if 10% reduction in skin would achieve

productivity target

• Hydraulic fracturing is the best alternative

Carbonate reservoirs

• Matrix stimulation if -2 to -3 skin would achieve productivity

target

• Acid fracturing can be cost-effective

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Selection of Technique (Cont‟d)

Drawdown Limit

In unconsolidated or friable sands, the max. allowable

pressure drop should not be exceeded in order to prevent

sand production

Limitation favours fracture stimulation to achieve target

rate at lower drawdown

Zonal Isolation

If vertical fracture growth into an aquifer or gas cap

cannot be controlled, matrix stimulation is a better choice

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Wellbore Cleanout

Perforations and tubular goods may become clogged with

deposits over a period of time

Deposits (products of corrosion, bacteria & scales, paraffin and asphaltene

buildup will restrict the well‟s flow capacity

Main purpose of technique is to restore flow capacity by

removing the wellbore damage

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Wellbore Cleanout (Cont‟d)

Methods

Mechanical

• Require a metal scraper and a coiled tubing unit (Figure 2)

• The coiled tubing could be used to circulate sand fill out of the

hole, as well as perforation wash „rotating jet tool‟ Chemical Treatment

• Consists of one or a combination of surfactants, organic

solvents, bactericides, scale removers/inhibitors, mutual

solvents and clay dispersant/stabilizers

Acid Treatment

• Involves pumping an acid and placing it at the restriction depth to

dissolve the restriction or weaken it for easy removal (Figure 3)

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Figure 2: Coiled Tubing Unit

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Figure 3: Acid Pumper

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Matrix Stimulation/Acidizing

Accomplished by injecting a fluid (e.g. acid or solvent) below

the fracturing pressure of the formation

Acid treatment process under wellbore cleanout is similar to

matrix stimulation process in sandstone formation; the acid

dissolves and/or disperse materials that impair well

production.

In carbonate formation, the acid dissolves the rock to createnew unimpaired (high conductivity) flow channels (i.e.

wormholes) between the wellbore and the formation (Figure 4) (Further reading: Refer to the provided article - „Stimulate the Flow‟)

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Figure 4: Neutron radiographs of wormholes formed during the dissolution of limestone by 0.25-MEDTA injected at pH 4.

Q = 0.01 cm-’/min Q = 0.025 cm3/min Q = 0.06 cmi/min Q = 0.15 cm’/min Q = 1.0 cni3/min Q = 3.0 crn3/min

Damt = 8.7 Damt = 3.5 . Damt= 1.5 Damt = 0.6 Damt = 0.09 Damt = 0.03

PVinj= 20.0 PVBT = 3.7 PVBT = 2.6 PVBT = 3.6 PVBT = 10.6 PVBT = 16.2

Source: Fredd, C.N. and Fogler, H.S. (1998): „Influence of Transport and Reaction on Wormhole Formation

in Porous Media‟, AIChE J., 44, 9, (Sept.), 1933-1949

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Fig 5a: Top view of wormhole structure, Test 1. Fig 5b: Side view of wormhole structure, Test 2.

Source: McDuff, D.; Jackson, S.; Shuchart, C.; and Postl, D.(2010):‟Understanding Wormholes in

Carbonates: Unprecedented Experimental Scale and 3D Visualization‟, (SPE 129329), JPT ,

Oct, 78-81.

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Treating Chemicals

Multiple fluids composed of base fluids and additives are selected based on

lithology, damage mechanism and well condition. The main treating fluid isselected to bypass the damage with acid or dissolve with solvents (in carbonate);

while its chosen to dissolve or disperse the principal damage (in sandstone)

Chemical Categories Solvents:

• Remove organic deposits (e.g. Paraffin)

Oxidizers:• Remove damage from polymers

Scale removers:

• Remove sulfate or oxide scales

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Chemical Categories

Acids:

• Remove carbonate and oxide scales

• Break polymer residues

• Stimulate carbonate formations

•

HF removes alumino-silicate (primarily clays) damage from sandstoneformations

• In carbonates, HCl or organic acids (formic or acetic) are used to etch

conductive paths between the wellbore and the formation

•In sandstones, mixtures of HCl and HF are used to remove drilling mud, fines(in-situ/generated), and perforation residue.

Acids are widely used for matrix stimulation because they are effective

against several types of damage and are relatively inexpensive.

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Application and Comparison of Acids

ACID STRENGTH FORMATION REMARKS

HCl15-28% by

weightCarbonate Highly corrosive (above )

Mud Acid 9% HCl+1% HFSilica

sandstone

HCl used prior to treatment to

remove + Highly corrosive

Acetic 10% by weight Carbonate Less corrosive than HCl but moreexpensive

Formic 9% by weight Carbonate

Less corrosive than HCl.

More corrosive and less

expensive than acetic acid

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Hydraulic Fracturing

What happens if fluid is pumped into a well faster than the the

fluid can escape into the formation?

Pressure rises and at some point something breaks.

The formation breaks, resulting in the wellbore splitting along

its axis as a result of tensile hoop stresses generated by the

internal pressure

“Hydraulic” fracture is created when the wellbore breaks or

the rock fractures due to the action of the hydraulic fluid

pressure

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Fracture direction and geometry

Fractures are always perpendicular to the minimum stress,except in formation with very complex geology

Since most wells are vertical and the smallest stress is the

minimum horizontal stress, the initial splitting results in avertical, planar parting in the earth

For relaxed geological environments, the minimum in-situ

stress is usually horizontal

In areas of acting tectonic compression (faulting), the min.

stress is vertical

Vertical Fracture

Horizontal Fracture

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Figure 6: Stress element and

preferred plane of

fracture

What if the least

principal stressbecomes the

highest?

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Types of Hydraulic Fracturing

Basically there are two types:

Propped Fractures

Acid Fracture

Propped Fracture• If the pumping rate is maintained at a rate higher than the fluid-loss

rate, the newly created fracture will continue to propagate and

grow (i.e. open more formation area)

• When pumping stops and the injected fluids leak off, the fracturewill close.

• To prevent this, measures must be taken to maintain the

conductive channel.

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Propped Fracture (Cont‟d)

• A propping agent is added to the hydraulic fluid to be transported

into the fracture• When pumping stops and fluid flows back from the well, the

propping agent remains in place to keep the fracture open

• Propping agent is generally sand or a high strength, granular

substitute for sand. [Figure 7(a)-(c)] • Expectedly after breakdown, fracture propagation rate and fluid

flow rate inside the fracture are dominated by fluid-loss behaviour

• Risk of a screen-out and subsequent problems of proppant

flowback and cleanout from the wellbore

• Not all of the fracture is usable (Figure 7)

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Figure 7(a): 20/40 Northern White fracturing sand.

Photo courtesy: Santrol Proppants.

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Figure 7(b): 20/40 SLC resin-coated sand.

Photo courtesy: Santrol Proppants

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Figure 7(c): CARBOEconoprop 20/40, a high-conductivity,

lightweight ceramic proppant from CARBO

Ceramics

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Figure 8

P S l

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3. Review Proppant Database finding proppants matching required mesh sizes,

formation closure stress and temperature

1. Calculate optimal fracture half-length

and conductivity

4. Select proppants with required conductivity

5. Sort selected proppants by price;

Select proppant flowback control additives

2. Determine applicable proppant mesh sizes

Proppant Selection

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Acid Fracture

• First attempt of HCl to prevent corrosion of w/b tubulars

in a limestone formation (observed “lifting pressure”enhanced)

• Any difference between acid and propped fracturing?

Means of achieving fracture conductivity after the

fracture closes; an etched pattern of voids on the

fracture faces and propping the faces apart,

respectively

• Operationally, acid fracturing is less complicated becauseno propping agents are used

• Risks of screen-out, flowback and cleanout associated

with propped fracture are eliminated

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Acid Fracture

• Barriers to effective acid penetration are:

•

The distance the acid travels along the fracture beforespending limits the effective length of an acidized fracture,

especially at high temperatures.

• Excessive fluid loss

Continuous acid corrosion and erosion of the fracture faces duringtreatment retard the deposition of an effective filter cake barrier

Acid leak-off is highly non-uniform and typically results in wormholes

and the enlargement of natural fractures and matrix permeability

Acid fractures are used in carbonates

Propped fractures are more appropriate for sandstones

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Length, Width and Conductivity

Fracture‟s length and width are function of formation

permeability For a low-k sandstone, what matters is the length of the

fracture. Fluid flows easily into the fracture from several

sections of the reservoir. For a high-k sandstone, the relevant factor is the width. The

aim is to reduce the pressure drop near the wellbore; this is

achieved with a “fat” fracture

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Proppant

Low permeability zone

Damaged zone

High permeability zone

Damaged zone

Figure 9: Length and width in high and low permeability sandstones

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Length, Width and Conductivity

In terms of flow rate:

• Fracturing a low permeable zone can lead to increase inproduction

• Fracturing a high permeable zone may accelerate

production

With regard to cumulative production:

•

Fracturing a low permeable zone can ensure a significantincrease in the ultimate recovery

• For a high-k zone, fracturing can facilitate achieving faster

ultimate recovery

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F l o

w

r a t e

Time

Low permeability

With stimulation

Without stimulation F l o w

r a t e

Time

High permeability

With stimulation

Without stimulation

Economic limit

Economic limit

Figure 10: Effect of fracturing on flow rates of low and permeable zones

F l o

w

r a t e

Time

Low permeability

With stimulation

Without stimulation

C u m

. P r o d .

Time

High permeability

Ultimate recovery

Figure 11: Effect of fracturing on total production of low and permeable zones

With stimulation

Without stimulation

Ultimate recovery

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Questions?

Thank you

pab 4323 l3

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